With the rapidly declining availability of hydrocarbon fuels, particularly from petroleum sources, there is a great need to extend efforts for the recovery of the petroleum to sources heretofore practically or economically unattractive and to the recovery of hydrocarbon fuels from alternate sources. A major potential source of petroleum, which has heretofore been virtually untapped because of the inability of most refineries to handle such crudes and the inability and expense of recovering them, are heavy oil deposits. Two basic methods have heretofore been applied in the recovery of such heavy oil deposits, namely; in situ combustion and steam injection methods. Both of these techniques have been limited by the fact that both require the burning of substantial amounts of the oil itself, or equivalent fuels, in order to reduce their viscosity and permit production thereof. This is true even with increased prices of oil. For example, to evaluate the economics of steam injection, the oil/steam ratio (OSR) is utilized. The OSR is the ratio of additional oil recovered for each ton of steam injected. Since it is necessary to burn about eight tons of fuel to get one hundred tons of steam, an OSR of 0.08 has a thermal balance of 0; i.e., you burn as much oil to generate the steam as you produce. Generally, wells in the Kern River Field of California operate with an OSR of 0.24, and are abandoned when they get below 0.15.
However, with the decontrol of heavy oil prices several years ago, substantial work has been done and commercial operations are presently under way utilizing steam recovery techniques for the recovery of heavy oil. In addition, the technology has progressed to the point where application of steam technology to other resource areas such as tar sands, diatomaceous earth, oil shale, and even residual light oil are technically feasible. However, until fairly recently, the state of the art techniques for heavy oil production by steam injection have produced only about 40% to 55% of the oil in place. This of course, is close to the ragged edge of being economic and leaves substantial volumes of oil unrecovered.
Most commercial operations, at the present time, are confined to the use of conventional steam boilers for the generation of steam. Usually, the lease crude is used as a fuel. However, when one considers that 80% to 85% of the cost of a steam injection operation is cost of the fuel, this obviously is a major factor. As a result, a number of alternate energy sources, some rather exotic, have been suggested, including petroleum coke, low BTU lignite coal, natural gas, almond hulls and tree prunings, solar energy, etc. However, except for solar energy, all suggested and used sources of energy for steam generation have the same problems and disadvantages.
First of all, conventional steam boilers waste about 19% of the fuel value in stack losses, about 3% to 20%, commonly 13%, in flow lines from the boiler to the wellhead and about 3% in the well bore at depths up to about 2900 feet and about 20% at depths below 2900 feet. As a matter of fact, at depths below 2900 feet, the steam has generally degraded to hot water. Considerable work has been done and some progress made in the elimination of well bore losses by the use of insulated tubing for the injection of steam. However, it is generally accepted that the practical limit for conventional steam injection is about 2,000 to 2,500 feet. This limit, of course, eliminates substantial volumes of heavy oil below this depth. For example, the National Petroleum Council has recently estimated that there are from about 1.6 to 2.1 billion barrels of heavy oil in California, Texas and Louisiana alone, which are not recoverable by conventional steaming methods.
In addition, numerous heavy oil reservoirs will not respond to conventional steam injection since many have little or no natural drive pressure of their own and, even when reservoir pressure is initially sufficient for production, the pressure obviously declines as production progresses. Consequently, conventional steaming techniques are of little value in these cases, since the steam produced is at a low pressure, for example, several atmospheres. Consequently, continuous injection of steam or a "steam drive" is generally out of the question. As a result, a cyclic technique, commonly known as "huff and puff" has been adopted in many steam injection operations. In this technique, steam is injected for a predetermined period of time, steam injection is discontinued and the well is shut in for a predetermined period of time, referred to as a "soak". Thereafter, the well is pumped to a predetermined depletion point and the cycle repeated. This technique has the disadvantages that it depends, for the recovery of oil, solely on a decrease in viscosity of the oil and the steam penetrates only a very small portion of the formation surrounding the well bore, particularly since the steam is at a relatively low pressure.
There are also known to be large amounts of untapped heavy oil in offshore locations. To date there have been no efforts to even test steaming in these reservoirs. Conventional boilers are obviously too large for offshore production platforms, even though it has recently been proposed to cantilever such a steam generator off the side of a production platform. However, in addition, such conventional steaming methods raise complex heat loss problems. Further, conventional boilers cannot use sea water as a source of steam because of the obvious fouling and rapid destruction of the boiler tubes.
One of the most formidable problems with conventional steam generation techniques is the production of air pollutants, namely, SO.sub.2, NO.sub.x and particulate emissions. By way of example, it has been estimated that when burning crude oil having a sulfur content of about 2%, without flue gas desulfurization and utilizing 0.3 barrels of oil as fuel per barrel of oil produced, air emissions in a San Joaquin Valley, Calif. operation would amount to about 40 pounds of hydrocarbons, 4,000 pounds of SO.sub.2, 800 pounds of NO.sub.x and 180 pounds of particulates per 1,000 barrels of oil produced. When these figures are multiplied in a large operation and a number of such operations exist in a single field, the problems can readily be appreciated. Consequently, under the Clean Air Act, the Environmental Protection Agency has set maximum emissions for such steaming operations, which are generally applied area wide, and states, such as California where large heavy oil fields exist and steaming operations are conducted on a commercial scale, have even more stringent limitations. Consequently, the number of steaming operations in a given field have been severely limited and in some cases it has been necessary to completely shut down an operation. The alternative is to equip the generators with expensive stack gas scrubbers for the removal of SO.sub.2 and particulates and to adopt sophisticated NO.sub.x control techniques. This, of course, is a sufficiently large cost to make many operations uneconomic. Further, such scrubbers also result in the production of toxic chemicals which must be disposed of in toxic chemical dumps or in disposal wells where there is no chance that they will pollute ground waters.
Another solution to the previously mentioned well bore losses has been proposed in which a low pressure burner is lowered down the well to generate steam adjacent the formation into which the steam is to be injected. The flue gas or combustion products are then returned to the surface. This, of course, has the definite disadvantages that the flue gas or combustion products must be cleaned up at the surface in the same manner, probably at the same cost, as surface generation systems. Further, the low volumetric rate of heat release attainable in such a burner severely limits the rate of steaming or requires a much larger diameter well.
It has also been proposed to utilize high pressure combustion systems at the surface of the earth. Such a system differs from the low pressure technique to the extent that the water is vaporized by the flue gases from the combustor and both the flue gaas and the steam are injected down the well bore. This has been found to essentially eliminate, or at least reduce or delay, the necessity of stack gas clean up and the use of NO.sub.x reduction techniques. The mixture conventionally has a composition of about 60% to 70% steam, 25% to 35% nitrogen, about 4% to 5% carbon dioxide, about 1% to 3% oxygen, depending upon the excess of oxygen employed for complete combustion, and traces of SO.sub.2 and NO.sub.x. The SO.sub.2 and NO.sub.x, of course, create acidic materials. However, potential corrosion effects of these materials can be substantially reduced or even eliminated by proper treatment of the water used to produce the steam. There is a recognized bonus to such an operation, where a combination of steam, nitrogen and carbon dioxide are utilized, as opposed to steam alone. In addition to heating the reservoir and oil in place by condensation of the steam, the carbon dioxide dissolves in the oil, particularly in areas of the reservoir ahead of the steam where the oil is cold and the nitrogen pressurizes or repressurizes the reservoir. In fact, in certain types of reservoirs it is believed that the nitrogen creates artificial gas caps which aid in production. As a result of field tests, it has been shown that the high pressure technique results in at least a 100% increase in oil production over the use of steam alone and shortening the time of recovery to about two-thirds of that for steam injection alone. Such tests have generally been confined to injection of steam utilizing the "huff and puff" technique, primarily because results are forthcoming in a shorter period of time and comparisons can be readily made. However, utilization of the high pressure technique in steam drive operations should result in even further improvements. A very serious problem, however, with the currently proposed above ground high pressure system is that it involves a large hot gas generator operating at high pressures and high temperatures. This creates serious safety hazards and, when operated by unskilled oil field personnel, can have the potential of a bomb. One solution to the problems of the heat losses, during surface generation and transmittal of the steam-flue gas mixture down the well, and air pollution, by generating equipment located at the surface, is to lower a combustor-steam generator down the well bore to a point adjacent the formation to be steamed and inject a mixture of steam and flue gas into the formation. This also has the above-mentioned advantages of lowering the depth at which steaming can be economically and practically feasible and improving the rate and quantity of production by the injection of the steam-flue gas mixture. Such a technique was originally proposed by R. V. Smith in U.S. Pat. No. 3,456,721. If such an operation is also carried out in a manner to achieve high pressure, the reservoir can also be pressurized or repressurized. Extensive work has been conducted on this last technique for the U.S. Department of Energy's Division of Fossil Fuel Extraction. While most of the problems associated with such a system have been recognized, by these and other prior art workers, to date practical solutions to these problems have not been forthcoming. In order to be effective, for steam injection, the power output of the combustor should be at least equivalent to the output of current surface generating equipment, generally above about 7MM Btu/hr. In order to be useful in a sufficiently large number of reservoirs, the output pressure must be above about 300 psi. The combustor must also be precisely controlled so as to maintain flame stability and prevent flame out, etc. Such control must also be exercised in feeding and maintaining proper flow of fuel and combustion supporting gas and combustion stoichiometry for efficient and complete combustion, thereby eliminating incomplete combustion with the attendant production of soot and other particulate materials, since excessive amounts of combustion suporting gas for stoichiometric combustion could contribute to corrosion and excessive amounts of fuel result in incomplete combustion and the production of soot and other particulates. A further problem is the construction of the combustor and its operation to prevent rapid deterioration of the combustion chamber and the deposition of carbonaceous materials on the walls of the combustion chamber. Thus, proper cooling of the combustion chamber is necessary, as well as protection of the walls of the combustion chamber. Efficient evaporation and control of the water are also necessary to produce dry, clean steam. Unless the combustor is properly controlled, in addition to introducing the water into the flue gas properly, the water will prematurely dilute the combustion mixture, resulting in incomplete combustion and creation of the water-gas reaction, as opposed to combustion, and prematurely cool the combustion mixture, again producing excessive soot and particulates. All of these last mentioned problems are greatly compounded by size limitations on the generator. Usually, wells will be drilled and set with casing having an internal diameter of 13" or less and, less than 7" in most cases. Thus, the downhole generator should have a maximum diameter to fit in 13" casing and most preferably to fit into a 7" casing. Obviously, the tool should be durable and capable of many start-ups, thousands of operating hours and many shutdowns. Again, because of the nature of the operation, the tool should be designed to be flexible in construction, to permit ready inspection, repair and adjustment.
A very serious problem in the use of high pressure generators is the maintenance of design pressure in the generator, particularly in down hole operations. Since the back pressure exerted on the generator by well fluids varies considerably, initially increasing as fluid is injected and then decreasing as fluid production progresses, the internal generator pressure varies from the design pressure. As the internal generator pressure decreases, the fuel and combustion supporting gas flow decrease and the combustor is operated at less than the design heat release and inefficient operation results.